|Publication number||US8127853 B2|
|Application number||US 13/036,737|
|Publication date||Mar 6, 2012|
|Filing date||Feb 28, 2011|
|Priority date||May 9, 2008|
|Also published as||US7896081, US20090277645, US20110155382|
|Publication number||036737, 13036737, US 8127853 B2, US 8127853B2, US-B2-8127853, US8127853 B2, US8127853B2|
|Inventors||Joseph W. Pallini, Rockford D. Lyle, Gregory M. Dunn|
|Original Assignee||Vetco Gray Inc.|
|Export Citation||BiBTeX, EndNote, RefMan|
|Patent Citations (38), Referenced by (9), Classifications (10), Legal Events (1)|
|External Links: USPTO, USPTO Assignment, Espacenet|
This application is a continuation of Ser. No. 12/118,443, filed May 9, 2008, U.S. Pat. No. 7,896,081, to issue Mar. 1, 2011.
This invention relates in general to subsea oil and gas well production, and in particular to a tieback connector extending from the subsea well to a platform at the surface.
Subsea wells typically have a subsea wellhead assembly at the seafloor. In some installations, a subsea production tree will be mounted on the wellhead assembly. The tree has valves connected to flowlines for controlling flow from the well. In another type of installation, a string of tieback conduit extends from the subsea wellhead assembly to a platform at the surface. A surface tree is mounted on the upper end of the tieback conduit. Some riser systems have inner and outer tieback conduits, each of which is run separately and connected by a tieback connector. The inner and outer tieback conduits make up the tieback riser in that type of system.
The inner tieback conduit is installed by connecting a tieback connector to the lower end of the conduit and lowering it into the bore of the subsea wellhead housing assembly. The tieback connector has a locking member that locks to the subsea wellhead housing or to the tapered stress joint at the bottom of the outer tieback conduit. The inner tieback connector also has a seal that seals to an internal component of the subsea wellhead housing assembly. Typical outer tieback connectors are locked to the exterior of the subsea wellhead housing assembly. Other outer tieback connectors are locked to the interior. An internal tieback connector typically has a mandrel with a sleeve on the exterior. The mandrel is connected to the inner tieback conduit and is capable of moving between an upper running-in position and a lower landed position in the subsea wellhead housing. An actuator holds the mandrel in the upper position until the actuator lands on structure in the wellhead housing. Then, downward movement of the inner tieback conduit causes the locking member to engage an internal profile in the subsea wellhead housing assembly.
The tieback apparatus of this invention has a sleeve and a mandrel installed within the sleeve. The mandrel is movable between an upper position and a lower position relative to the sleeve. In one mode, the movement is without rotation of the inner tieback conduit, and in another mode, the movement is caused by rotation. The mandrel has an exterior tapered portion with a set of external threads. The threads increase in diameter from a lower end to an upper end. A radially expansible load ring is carried by the sleeve. The load ring has a set of internal threads that ratchet over the external threads as the mandrel moves from the upper position to the lower position. The load ring has an external profile that mates with an internal profile of the subsea well assembly when the mandrel is in the lower position. In the embodiment shown, the internal profile is located within the lower portion or stress joint of an external riser. The mandrel is rotatable relative to the sleeve and the load ring while in the lower position. This rotation causes the internal threads to advance upward relative to the external threads to further expand the load ring into engagement with the internal profile of the subsea well assembly. In an alternate mode of operation, all of the expansion of the load ring is caused by rotation.
In one embodiment, the internal profile of the subsea well assembly is located within a stress joint of a riser that is connected to the subsea wellhead housing. The load ring thus engages the internal profile in the riser, connecting the tieback conduit to the mandrel.
In addition to locking to the riser stress joint, optionally, the tieback connector also locks to an internal profile located within the subsea wellhead housing. A locking member is carried by the sleeve below the load ring. The mandrel has an exterior cam surface that slides downward relative to the locking member to expand it outward at the same time as the load ring is being expanded outward. Preferably, the mandrel has threads above the cam surface that mate with threads of the locking member so that when the mandrel is rotated to further expand the load ring, it also engages the locking member threads with the mandrel threads. In the preferred embodiment, the locking member comprises a plurality of dogs spaced around the sleeve.
In this example, a second casing hanger 17 is landed within casing hanger 13. Casing hanger 17 is attached to a string of casing that extends to a greater depth in the well than the casing attached to casing hanger 13. A second packoff assembly 19 secures the annulus between casing hangers 13 and 17.
In this example, a lockdown member 21 lands on top of casing hanger 13 to prevent upward movement of casing hanger 13. Lockdown member 21 is a tubular member that is secured by a split lock-ring 23 or a segmented dog ring to an internal groove or profile 27 formed in the bore of the wellhead housing 11. Lock ring 23 is energized or expanded to the locked position by a packoff assembly 25 that is wedged between lockdown member 21 and the bore of wellhead housing 11. Other arrangements of the structure within wellhead housing 11 are feasible, including mounting the second casing hanger on top of the first casing hanger, rather than within. Also, lockdown member 21 may be eliminated in some installations. The arrangement of this example is employed for a high pressure and high temperature well.
In this example, an external riser 29, which is an outer tieback conduit, connects to an exterior profile on wellhead housing 11 and extends upward to a surface platform. A gasket 31 seals riser 29 to the interior of wellhead housing 11. Riser 29 has an internal profile 33 that in this instance comprises a plurality of rounded, parallel grooves, but other configurations are feasible.
An inner tieback connector 35 is employed to connect a string of inner tieback conduit (not shown) to the subsea well assembly, which includes wellhead housing 11 and its internal components, as well as the lower end or stress joint of riser 29. Inner tieback connector 35 has a mandrel 37, which is an inner tubular member, that is secured to the string of conduit. Mandrel 37 has an upper external set of threads 39 that are located on a tapered or conical surface. The lower end of external threads 39 has a smaller diameter than the upper end, as shown in
An expandable load ring 47 is carried by mandrel 37. Load ring 47 has a set of tapered internal threads 49 that have the same taper as external threads 39. Threads 49 will mesh with external threads 39 while mandrel 37 is in the lower position shown in
Referring back to
Sleeve 59 is mounted to mandrel 37 so that mandrel 37 can move from the upper running in position shown in
Referring still to
Referring again to
A plurality of anti-rotation keys 83 will snap into engagement with a mating slot 85 formed in lockdown member 21 in this example. As shown in
In this embodiment, in addition to locking inner tieback connector 35 to riser 29 with load ring 47, it is also locked to an internal component of subsea wellhead housing 11. In this example, inner tieback connector 35 has a locking member comprising a plurality of dogs 89 spaced around the circumference of sleeve 59. Referring to
Also, each dog 89 may have a segment of a thread or groove 93 on its interior surface. Threads 93 are located on an inner surface of each dog 89 and will mate with lower external threads or grooves 43 on mandrel 37. Threads 93 will loosely engage threads 43 and ratchet when mandrel 37 is moving downward relative to dogs 89. Dogs 89 are preferably retained within the windows of sleeve 59 by upper and lower tabs 97 (
In operation, inner tieback connector 35 will be assembled as illustrated in
The operator then rotates the inner tieback conduit, which causes mandrel 37 to rotate. Sleeve 59 may initially rotate a short increment, but its anti-rotation keys 83 will soon spring into slots 85, preventing further rotation of sleeve 59, dogs 89, and load ring 47. The rotation of mandrel 37 causes relative axial movement between mandrel 37 and load ring 47. Load ring 47 moves upward, and mandrel 37 downward into tight, preloaded engagement with riser profile 33. Threads 93 of dogs 89 engage lower threads 43 on mandrel 37 but will not make-up tightly. The remaining downward movement of mandrel 37 that occurs while it is rotating causes seal 81 to come into full sealing engagement with casing hanger 17. Afterward, the operator would run tubing, complete the well and install a surface production tree at the platform.
The completed assembly thus locks internal connector 35 both to the stress joint of riser 29 as well as to an internal component of the assembly of subsea wellhead housing 11. If riser 29 were inadvertently disconnected from wellhead housing 11, connector 35 would still remain attached to its connection with lockdown member 21 after a small amount of travel of riser 29. This connection is through the engagement of dogs 89 with profile 91 and the threaded engagement of mandrel threads 43 and dog threads 93. If mandrel 37 and sleeve 59 both began to move upward, profiles 95 of dogs 89 would come into full load bearing contact with lockdown member profile 91, preventing further upward movement. The tight make-up of load ring 47 is not hampered by the loose engagement of dogs 89 with lockdown member profile 91.
In the first method of operation, referring to
The embodiment of
The second feature that differs is to replace clamp 57 (
While the invention has been shown in only two of its forms, it should be apparent to those skilled in the art that it is not so limited but susceptible to various changes without departing from the scope of the invention. For example, in some cases the locking dogs could be eliminated, with the sole connection being to the external riser. Alternately, the locking dog arrangement could be employed with other tubular members wherein another outer tubular member would take the place of lockdown member 21 and another inner tubular member would take the place of mandrel 37. Also, if an external riser is not employed, the load ring could be positioned lower and engage structure within the subsea wellhead housing.
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|US20130020087 *||Feb 11, 2011||Jan 24, 2013||Jean Guesnon||Riser section connector with flanges and external locking ring|
|U.S. Classification||166/345, 166/367, 166/341, 166/77.1, 166/339, 166/338, 285/18|